Low cost rigless intervention and production system

ABSTRACT

A downhole system comprises (a) a wellbore deployable container comprising an operational control circuit and a power source operationally in communication with the operational control circuit, each disposed within the container; a wellbore deployable, controllable downhole electronic frac fluid flow control module further comprising a wellbore deployable container receiving seat; and a data handling circuit; (b) a wellbore deployable, data transmission capable gauge deployable near the control module; and (c) a surface system operatively in communication with the operational control circuit and/or the control module. The control module, container, and data gathering gauge may be deployed within the wellbore; the surface system deployed at the wellbore&#39;s surface; communications established between the gauge, surface system, and operational circuit; and a data transmission command issued from the surface system to the container to trigger transmitting data from the container to the surface system to control a wellbore fluid process.

RELATION TO OTHER APPLICATIONS

This application claims the benefit of U.S. Provisional Application No. 61/159,589, filed on Mar. 12, 2009 and is a continuation-in-part of U.S. application Ser. No. 12/463,523 filed on May 11, 2009 and of U.S. application Ser. No. 12/550,777 filed on Aug. 31, 2009.

BACKGROUND OF THE INVENTION

Currently, deployment and retrieval of downhole devices such as pumps and production pipes requires a rig, which can be costly. Further, wellbore tubulars tend to be made of metals which may corrode and are rigid, leading to less flexible installation procedures.

Over the past 10 years, the application of non-metallic materials in flowlines such as in those used wellbores has proven itself an alternative to metallic flowlines. Metallic materials tend to be less resistant to corrosion and/or chemicals and their rigidity is a factor to be taken into consideration during installation and use.

Providing power to equipment needing power in a wellbore has meant providing long runs of cabling, self-powered equipment, or both downhole. These methods are costly and, in the case of systems using a power cable, can require extensive rework if the power cable should go bad. Further, it is not possible to provide power or communications in a main or lateral wellbore where no continuous tubing exists since there is a break in the cable.

There is a need for a system that monitors data in the wellbore during and after the frac job. Such a system may be used in horizontal sections of the well to separate the well into multiple zones to collect data during a frac and transfer data and commands.

BRIEF DESCRIPTION OF THE DRAWINGS

The various drawings supplied herein are representative of one or more embodiments of the present inventions.

FIG. 1 is a diagram of an exemplary system embodiment;

FIGS. 2 and 3 are perspectives in partial cutaway of an exemplary tube illustrating embedded umbilical and/or electrical cables;

FIG. 4 is an exemplary plan view of a tube with filters; and

FIG. 5 is an exemplary plan view of a tube with deformable material.

FIG. 6 is a drawing in partial perspective of a wellbore illustrating a pipeline where the use of wireless short hop power transfer provides the ability to eliminate a cable through the deviated section of the wellbore;

FIG. 7 is a drawing in partial perspective of a receiver, and FIG. 7 a is an illustration of an exemplary RF receiver;

FIG. 8 is a drawing in partial perspective of a cable;

FIG. 9 is drawing in partial perspective of a representative system;

FIG. 10 is drawing in partial perspective of a frac ball system;

FIG. 11 is drawing in partial perspective of a frac ball system; and

FIG. 12 schematic representation of a container comprising an operational circuit and a power source.

DETAILED DESCRIPTION OF EXEMPLARY EMBODIMENTS

As used herein, “tube” will be understood by one of ordinary skill in these arts to include a production pipe, an injection pipe, a portion of a tubular to be used within a wellbore, a portion of a tubular to be used within another tubular, or the like.

Referring now to FIG. 1, rigless intervention and production system 10 comprises flexible, non-metallic, substantially continuous tube 20 and connector 30.

Tube 20 comprises a high temperature tolerant, non-metallic material such as a carbon-enhanced, resin-based themoplastic, a fluoropolymer, a polyemide material, or the like, or a combination thereof. Kevlar® or other similar materials may be used as part of the tube wall to strengthen tube 20 such as to improve pressure collapse and burst properties.

In typical embodiments, a predetermined portion of tube 20 is dimensioned and configured to be deployed within wellbore 100, with the predetermined portion of tube 20 further comprising first connection end 24 disposed distally from fluid outlet 22. Tube 20 is typically dimensioned and configured into continuous lengths to reach a desired wellbore depth, typically from around between 6,000 feet to around 10,000 feet. In typical embodiments, tube 20 can withstand a maximum working pressure of around 15,000 psi (1,034 bar).

Referring additionally to FIGS. 2 and 3, tube 20 may further comprise umbilical 26 and/or electrical cable 27 which may be disposed about a predetermined portion of tube 20, such as about an interior or exterior surface of tube 20, or at least partially embedded into tube 20. In certain configurations, umbilical 26 may further comprise electrical cable 27.

Annulus 28 of tube 20 is typically dimensioned and configured to allow fluids to be pumped into wellbore 100.

Connector 30 is typically attached to first connection end 24 and dimensioned and configured to sealably attach tube 20 to tool 110 which is deployable within wellbore 100, e.g. pump 110 a (not specifically shown in the figures), downhole gauge 110 b (not specifically shown in the figures), sensors 110 c (not specifically shown in the figures), or the like, or a combination thereof. Tools 100 such as downhole gauge 110 b may be used to optimize production from wellbore 100. For example, downhole gauge 110 b may be dimensioned and configured to measure pressure of injected water near the bottom of wellbore 100, temperature of injected water near the bottom of wellbore 100, or the like, or a combination thereof. As used herein, “wellbore” and “well” may be used synonymously, as the context requires.

Sensors 110 c may be embedded into tube 20 such as during the manufacturing process. These sensors 110 c may comprise induction system sensors for formation evaluation and fluid evaluation; radio frequency identification sensors (RFID); pressure and temperature sensors, or the like, or combinations thereof. Sensors 110 c may be operatively connected to cable 27, e.g. using wired or wireless connections, umbilical 26, or to a cable disposed outside tube 20. Fiber wire 28 may also be embedded or otherwise disposed inside tube 20 and used for sensing downhole data such as data regarding production status, fluid configuration, fluid flow, fluid density, microseismic data, strain, pressure, temperature, or the like, or a combination thereof. As will be apparent to one of ordinary skill in these arts, sensor 110 c may be a plurality of sensors 110 c embedded at a corresponding plurality of locations in tube 20 or gathered into less than a corresponding plurality of locations in tube 20. Sensors 110 c may further comprise one or more coils dimensioned and configured to provide formation evaluation data, data communications, or the like, or a combination thereof.

In certain embodiments, tube spooler 40 is operatively connected to tube 20, i.e. tube 20 may be spooled and/or unspooled from tube spooler 40. Tube spooler 40 may comprise a power cable spooler or a combination of a power cable and a tube spooler.

Vehicle 130 may be part of rigless intervention and production system 10 and dimensioned and configured to accept tube spooler 40. One or more tube spoolers 40 and/or power cable spoolers may be located in the same unit for deployment, e.g. vehicle 130.

In currently contemplated embodiments, vehicle 130 comprises mast 132 and controller 134. Controller 134 is operatively in communication with tube spooler 40. Controller 134 controls the tension on tube 20, depth of tube 20 into wellbore 100, as well as control the starting and stopping of tube spooler 40. Controller 134 may be an electro-hydraulic controller, an electronic controller, or the like, or a combination thereof.

Rigless intervention and production system 10 may further comprise power generator 50. Typically, power generator 50 is a steam-powered electricity generator disposed at or near a surface location of wellbore 100. Power generator 50 may be in fluid connection with fluid outlet 22 to allow use of water from wellbore 100 obtained through fluid outlet 22 to be turned into steam to provide power for power generator 50. In currently envisioned embodiments, power generator 50 may be dimensioned and configured to use natural gas to generate heat to boil the water into steam for use by power generator 50. The water and natural gas may be obtained from wellbore 100, transported from a remote location, or the like, or a combination thereof.

Injector 60 may be present and operatively in fluid communication with tube 20 and used at wellhead 102 for the deployment of the system in wellbore 100. In these embodiments, injector 60 is dimensioned and configured for injection of fluids into wellbore 100 from the surface through a predetermined portion of tube 20. These fluids are typically usable for water injection suitable for well desalination or chemical injection.

Tube stop 120, which may include devices such as packers, may be deployed in wellbore 100 to secure tube 20 to a predetermined location in wellbore 100, such as near well perforations.

In further embodiments, a tool such as packoff unit 130 or tube hanger (not shown in the figures) is dimensioned and adapted to secure tube 20 inside wellbore 100 near wellhead 102. Tool 130 would typically be attached to the casing wall.

In certain embodiments, tube 20 further comprises a material disposed about an outer surface of tube 20. This material may be disposed along one or more predetermined lengths of tube 20 that match predetermined geological zone 104 in wellbore 100 that needs to be isolated. The material is configured and adapted to swell when in contact with a fluid, such as hydrocarbon or other fluids such as water, such that the material swells and seals the area between the outside of flexible non-metallic continuous tube 20 and well casing 104 or a geological formation when the material gets in contact with the activating fluid. For embodiments where the geographical zone comprises a plurality of zones in wellbore 100, the material may be disposed along different lengths of tube 20 where each such length matches one of the geological zones. This configuration can be used to isolate a zone in wellbore 100 where metallic production tube may be leaking. In this case, tube 20 can be deployed through the production tube and the production would then continue through tube 20 as opposed to the original production tube.

By way of example and not limitation, in certain embodiments, isolation material such as rubber formation isolation material can be attached to packoff unit 130, tube 20, or both, either permanently or removably. This material may be swell when in contact with a fluid, such as hydrocarbon or other fluids such as water, such that the material swells and seals the area between the outside of flexible non-metallic continuous tube 20 and well casing 104 or a geological formation when the material gets in contact with the activating fluid.

Referring now to FIG. 6, system 10 is dimensioned and configured to provide wireless communication of electromagnetic energy to and in wellbore 100 and its components such as to and in components in main wellbore 120 and lateral wellbore 122. As used herein, electromagnetic energy includes energy usable for power, data, or the like, or a combination thereof.

In a typical embodiment, system 10 comprises first module 20, which further comprises self-resonant coil 50 (FIG. 7); electromagnetic energy transmission cable 30 which is dimensioned and adapted to be deployed in wellbore 100; and second module 22, which further comprises its own self-resonant coil 50 and is located at a second distance from first module 20 within wellbore 100. Second module 22 is operatively in communication with electromagnetic energy transmission cable 30 such as by physical attachment.

Referring additionally to FIG. 7, first module 20 is typically located at a first distance with respect to wellbore 100, e.g. near the surface of wellbore 100, and typically comprises one or more self-resonant coils 50 which are typically coupled inductively to oscillating circuit 60. In a strongly coupled regime, first module 20 is dimensioned and configured to allow its self-resonant coil 50 to transfer non-radiative power transfer over a predetermined distance which, in a preferred embodiment, may be up to 8 times the radius of self-resonant coil 50. For example, in currently preferred embodiments, self-resonant coil 50 comprises electromagnetic energy conducting wire 20 a having a total length L and cross-sectional radius CR wound into a helix of N turns with radius R and height H. The distance between first and second modules 20,22 (FIG. 6) may be between around 1 times the radius CR to around 8 times the radius CR.

Referring back to FIG. 6, second module 22 and its one or more self-resonant coils 50 (FIG. 7) are typically located at a second distance into wellbore 100, e.g. inside wellbore 100, and are operatively in communication with electromagnetic energy transmission cable 30 such as by physical attachment. Second module 22 typically comprises one or more self-resonant coils 50 which are dimensioned and adapted to convert electromagnetic energy from first module 20 into electrical energy, as will be understood by those of ordinary skill in these arts.

In second module 22, self-resonant coil 50 (FIG. 7) is typically coupled inductively to a resistive load, which, by way of example and not limitation, may be one or more gauges 40, e.g. a pressure and/or temperature gauge, where such gauges 40 are located deeper into wellbore 100. The inductive coupling may be wirelessly or via a cable such as cable 30 or another cable (not shown in the figures).

Second module 22 may further comprise a pulse receiver, an RF receiver, or the like, or a combination thereof (an exemplary RF receiver is shown at 23 in FIG. 7 a). Suitable RF receivers are manufactured by GAO RFID, 93 S. Jackson Street #57665, Seattle, Wash. 98104-2818. Second module 22 can be located at a predetermined location such as where there may not be a continuous pipe from main wellbore 100 into lateral wellbore 122, e.g. at or near the entrance of lateral wellbore 122. In certain contemplated embodiments, energy can be transferred from main wellbore 100 to lateral wellbore 122 using a plurality of first modules 20 (the plurality are not shown in the figures) and then on to second module 22 which converts the energy into electrical energy. Data may also be transmitted between one or more second modules 22 and one or more first modules 20.

Referring additionally to FIG. 8, electromagnetic energy transmission cable 30 typically comprises center conductor 32 and ground 34. Ground 34 is most typically a metal sheath or tube used to provide an electrical ground return. Cable 30 is of a type suitable for use in wellbores 100 and/or, e.g., 122, as will be familiar to those of ordinary skill in these arts. Electromagnetic energy transmission cable 30 is dimensioned and configured to carry electrical power energy, data, or the like, or a combination thereof. Data communication utilizing electromagnetic energy transmission cable 30 typically comprises transferring data from one or more modules 22 (FIG. 6) deeper in wellbore 100 or 122 (FIG. 6) to a module closer to the surface, e.g. first module 20 (FIG. 6).

Referring back to FIG. 6, in currently contemplated embodiments, first and second modules 20,22 may be deployed inside production tubing 110, and their respective coils 50 (FIG. 7) are dimensioned and adapted to allow for power transfer inside production tubing 110, for example at spacing distances of around 2 meters. It is contemplated that first and second modules 20,22, when installed inside production tubing 110, are to be further dimensioned and configured to minimize restriction of fluids such as hydrocarbons flowing in production tubing 110, e.g. fluids would flow through or around the modules 20,22.

It is understood that a plurality of first and second modules 20,22 may exist in system 10. Further, in certain contemplated embodiments, first and second modules 20,22 are selectively insertable and retrievable from inside wellbore 100 such as to allow running logging tools in wellbore 100.

Referring now to FIG. 9, in a further embodiment, system 10 may be dimensioned and configured for wireless communications from main bore 210 to lateral bore 212 in wellbore 200. In this configuration, system 10 typically comprises surface power system 300 which is dimensioned and adapted to generate electromagnetic energy to be transmitted into wellbore 200. Such power systems are well known to those of ordinary skill in these arts. Power system 300 may further comprise data processing capabilities, e.g. a microprocessor and memory, and be used to process data received from a device deployed downhole in wellbore 200, e.g. gauge 240. First module 220 is operatively in communication with surface power system 300 such as by a wired and/or wireless connection. Cable 230 is disposed proximate the outside of tubing 210 and cable 232 is disposed proximate the outside of tubing 212 which is deployed in lateral bore 222 of wellbore 200 during the deployment of tubing 212. A plurality of second modules 222 may be present and operatively in communication with first cable 230 where at least one of the plurality of second modules 222 is deployed in lateral bore 222. A predetermined number of second modules 222, e.g. each such second module 222, may further comprise a pulse receiver, an RF receiver, or the like, or a combination thereof.

In certain configurations, first module 220 comprises coil antenna 224 deployed in main wellbore 210 of wellbore 200. Further, a predetermined number of the plurality of second modules 222, typically each such second module 222, comprises its own coil antenna 224, with each such coil antenna 224 being mounted on the outside of production tubing 210 deployed in wellbores 220, 222. In currently preferred embodiments, coil antenna 224 of second module 222 located in lateral wellbore 222 is dimensioned and configured to transmit data to first module 220 located in main wellbore 220, and lateral antenna 224 of first module 220 is dimensioned and configured to transmit data to the surface system 300.

System 10 may further comprise second cable 232 deployed in wellbore 200; wellbore device 240 deployed in wellbore 200; and distribution module 224 located proximate entrance 222 a of lateral wellbore 222. Wellbore device 240, which may be a gauge, sensor, flow control device, or the like, or a combination thereof, is operatively coupled to second cable 230 to permit electromagnetic energy to pass between wellbore device 240 and second cable 230. Distribution module 222 is typically dimensioned and adapted to receive electromagnetic energy and route the electromagnetic energy into second cable 230.

System 10 may further comprise one or more wireless power crossover module 250 deployed in a pipe disposed outside wellhead 204 to interface with module 240 inside wellbore 200. Wireless power crossover modules 222 are wirelessly coupled to provide power into wellbore 200 as well as data communication from inside wellbore 200 to a device such as a subsea pod located proximate to wellhead 204 without the need for a wellhead penetration.

In certain embodiments, system 10 may further comprise safety valve 270 dimensioned and configured to allow electromagnetic energy to wirelessly communicate through 270 safety valve, bypassing 270 safety valve without affecting its operations.

Referring now to FIGS. 10-12, downhole system 400 may comprise one or more containers 410 dimensioned and configured for deployment in wellbore 100; seat 420 dimensioned and configured for deployment in wellbore 100; one or more gauges 430 dimensioned and configured for deployment in the wellbore 100 near one or more containers 410; controllable downhole electronic frac fluid flow control 440 dimensioned and configured for deployment in wellbore 100; and surface system 450.

Referring specifically to FIG. 12, each container 410 typically comprises operational circuit 412 and power source 415, either or both of which may be disposed within container 410.

Operational circuit 412 may further comprise data collection circuit 413 dimensioned and configured to gather and store at least one of frac pressure data or temperature data and electromagnetic communications circuit 414 dimensioned and configured to obtain data from a downhole gauge such as gauge 430.

Data collection circuit 413 is typically dimensioned and configured to gather and store predetermined data stored in downhole electronic frac fluid flow control 440. These data may include pressure, temperature, flow, water cut, sleeve position, and the like, or a combination thereof. Electromagnetic communications circuit 414 is typically operatively in communication with data collection circuit 413.

Power source 415 is operationally in communication with operational circuit 412 and may be a battery, fuel cell, or the like, or similar to first module 20, electromagnetic energy transmission cable 30, and second module 22 as described above. Container 410 is typically is built around the electronics it is to house and may be substantially spherical but can be of any appropriate shape, e.g. ovoid or elliptical. Container 410 typically comprises a material that can withstand frac pressure and erosion, such as phenolic.

In certain contemplated embodiments, container 410 is placed as a separate module located as part of a frac or production string deployed in wellbore 100. Container 410 may be dimensioned and configured to seal wellbore 100 or, alternatively, to be deployed with coil tubing, slick line or other means in the well for retrieval of the data stored in the electronic of the seat, frac control module or gauge module.

Seat 420 is typically further dimensioned and configured to receive one of the containers 410. In a currently envisioned embodiment, each container 410 will be received by its own seat 420.

Gauge 420 is typically associated with a specific container 410 and, more typically, disposed proximate or on at least one of seat 420 or in a separate module in a pup joint assembly deployed in wellbore 100. In certain contemplated embodiments, gauge 430 further comprises a pressure and temperature gauge, electronics to condition the gauge signal, an analog to digital converter, a processor and memory to store the information, and an electromagnetic communications system to transfer data from gauge 430 to container 410. Gauge 410 is typically disposed proximate to or as part of downhole electronic frac fluid flow control 440.

Controllable downhole electronic frac fluid flow control 440 is dimensioned and configured for deployment in wellbore 100. Downhole electronic frac fluid flow control 440 is further typically dimensioned and configured to control fluid flow within wellbore 100. The fluid flow may be fluid flow from a reservoir to the inside of wellbore 100, the flow of frac fluid from wellbore 100 into the reservoir, or the like, or a combination thereof. Downhole electronic frac fluid flow control 440 typically comprises battery operated DC motor 442 (not shown in the figures) and valve 444 (not shown in the figures) dimensioned and configured to operate downhole electronic frac fluid flow control 440, i.e. to open and close valve 444 and thus permit flow of fluid within wellbore 100. Valve 444 may be a ball and seat valve.

Downhole electronic frac fluid flow control 440 is dimensioned and configured to be operated by a command issued from surface system 450, from container 410 (e.g. one lowered in wellbore such as with EM communications), or the like, or a combination thereof.

In certain contemplated embodiments, container 410 moves downhole electronic frac fluid flow control 440, e.g. to open it for the frac fluid to reach the reservoir to frac.

Surface system 450 is operatively in communication with operational circuit 412 disposed within container 410, the downhole electronic frac fluid flow control 440, or the like, or a combination thereof. Surface system may comprise electromagnetic communications module 452 dimensioned and configured to communicate with container 410 and interface 454 to a personal computer.

In the operation of preferred embodiments, a wellbore fluid may be processed by deploying one or more controllable downhole electronic frac fluid flow control 440 to a set of first predetermined positions in wellbore 100; deploying one or more containers 410 to a second set of predetermined positions in wellbore 100; deploying one or more gauges to a third set of predetermined positions in wellbore 100; deploying surface system 450 at a surface of wellbore 100; establishing communications between gauge 430 and operational circuit 412 disposed within container 410; establishing communications between surface system 450 and operational circuit 410 disposed within container 410; issuing a data transmission command from surface system 450 to container 410; and transmitting a first predetermined set of data from container 410 to surface system 450 upon receipt of the data transmission command from surface system 450. The first predetermined set of data may include data useful for formation monitoring, pump optimization, or the like, or a combination thereof.

As will be understood by one of ordinary skill in the downhole tool arts, multiple containers 410 can be deployed to be located proximate each frac control module 440, e.g. on or near the top of a corresponding frac control module 440. Container 410, once deployed, may be retrieved the surface of wellbore 100 and its data retrieved at the surface.

As described above, each gauge 430 can be integrated into frac control module 440, deployed proximate to downhole electronic frac fluid flow control 440, or be located on a separate container deployed near frac control module 440. One or more of gauges 430 may gather a second predetermined set of data and provide that second predetermined set of data to surface system 450 upon receipt of a data transmission command from surface system 450. The second predetermined set of data, which may include pressure data, temperature data, flow data, water cut data, control position data, or the like, or a combination thereof, may be stored in downhole electronic frac fluid flow control 440 for retrieval at a later date by container 410 with the electronics.

The wellbore fluid process may be a frac fluid process, a wellbore chemical process, a monitoring process, or the like, or a combination thereof. One or more of gauges 430 may be a sleeve gauge used to collect data after the frac, e.g. for build up tests. Gauge 430 is typically deployed without the need for a downhole wired communication connection to gauge 430 and the data are preferably retrieved wirelessly.

Data communications may be establishing between downhole electronic frac fluid flow control 440 and a predetermined module 400 deployed in wellbore via slickline, coil tubing, pumping or any other means to deploy hardware in the wellbore. The data are preferably retrieved wirelessly.

Wellbore 100 may comprise a horizontal section. At such sites, downhole electronic frac fluid flow control 440 and container 410 may be used to separate wellbore 100 into separate sections, with downhole electronic frac fluid flow control 440 and container 410 collecting data during a frac and transfer data and commands between the frac control and the container.

Container 410 may comprise a ball and seat which may be used to aid in isolating a wellbore zone, e.g. during an acid jobs to clean the formation face at the well. This may include collecting data at seat 420 and transferring these data to container 410 for storage.

The foregoing disclosure and description of the inventions are illustrative and explanatory. Various changes in the size, shape, and materials, as well as in the details of the illustrative construction and/or a illustrative method may be made without departing from the spirit of the invention. 

1. A downhole system, comprising: a. a container dimensioned and configured for deployment in a wellbore, the container further comprising: i. an operational control circuit disposed within the container; and ii. a power source disposed within the container, the power source operationally in communication with the operational control circuit; b. a controllable downhole electronic frac fluid flow controller dimensioned and configured for deployment in the wellbore, the controllable downhole electronic frac fluid flow controller further comprising: i. a seat dimensioned and configured for deployment in the wellbore as part of the controllable downhole electronic frac fluid flow control, the seat further dimensioned and configured to receive the container; and ii. a data handling circuit; c. a gauge dimensioned and configured for deployment in the wellbore near the frac control module, the gauge further dimensioned and configured for data transmission; and d. a surface system, operatively in communication with at least one of (i) the operational control circuit disposed within the container or (ii) the downhole electronic frac fluid flow control data handling circuit.
 2. The downhole system of claim 1, wherein the operational circuit further comprises: a. a data collection circuit dimensioned and configured to gather and store at least one of frac pressure data or temperature data; and b. an electromagnetic communications circuit dimensioned and configured to obtain data from a downhole gauge, the electromagnetic communications circuit operatively in communication with the data collection circuit.
 3. The downhole system of claim 1, wherein the data collection circuit is further dimensioned and configured to gather and store a first predetermined set of data.
 4. The downhole system of claim 3, wherein the first predetermined set of data are stored in the downhole electronic frac fluid flow control.
 5. The downhole system of claim 3, wherein the first predetermined set of data comprise at least one of pressure data, temperature data, flow data, water cut data, and sleeve position data.
 6. The downhole system of claim 1, wherein the gauge is disposed proximate at least one of the seat or in a separate module in a pup joint assembly deployed in the wellbore.
 7. The downhole system of claim 1, wherein the gauge further comprises: a. a pressure and temperature gauge; b. electronics to condition a signal in the gauge; c. an analog to digital converter; d. a processor and memory to store data; and e. an electromagnetic communications system to transfer the data from the gauge to the container.
 8. The downhole system of claim 1, wherein the gauge is disposed either proximate to or as part of the downhole electronic frac fluid flow control module.
 9. The downhole system of claim 1, wherein the downhole electronic frac fluid flow control module is dimensioned and configured to be operated by at least one of (i) a command issued from the surface system or (ii) from the container.
 10. The downhole system of claim 1, wherein the surface system comprises: a. an electromagnetic communications module dimensioned and configured to communicate with the container; and b. an interface to a computer.
 11. The downhole system of claim 1, wherein the power source further comprises: a. a first module, the first module comprising a self-resonant coil dimensioned and adapted to provide a wireless interface to an electromagnetic energy transmission cable which is dimensioned and adapted to be deployed in the wellbore; and b. a second module operatively in communications with the first module, the second module further comprising its own self-resonant coil to receive energy, the second module located at a predetermined distance from the first module within wellbore.
 12. A method of controlling a fluid process in a wellbore, comprising: a. deploying a controllable downhole electronic frac fluid flow control module to a first predetermined position in a wellbore; b. deploying a container to a second predetermined position in the wellbore, the container further comprising: i. an operational circuit disposed within the container; ii. a power source disposed at least partially within the container, the power source operationally in communication with the operational circuit; and iii. a container ball and seat; c. deploying a gauge to a third predetermined position in the wellbore, the gauge dimensioned and configured to gather a first predetermined set of data; d. deploying a surface system at a surface of the wellbore; e. establishing communications between the gauge and the operational circuit disposed within the container; f. establishing communications between the surface system and the operational circuit disposed within the container; g. issuing a data transmission command from the surface system to the container; and h. transmitting a predetermined set of data from the container to the surface system upon receipt of the data transmission command from the surface system.
 13. The method of claim 12, further: a. deploying a gauge module proximate to the downhole electronic frac fluid flow control module; b. using the gauge to gather a second predetermined set of data; and c. providing the second predetermined set of data to the surface system upon receipt of a data transmission command from the surface system.
 14. The method of claim 13, further comprising using the gauge to collect data after a frac process for build up tests.
 15. The method of claim 12, wherein the fluid process is at least one of a frac fluid process, a wellbore chemical process, or a monitoring process.
 16. The method of claim 12, further comprising establishing data communications between the downhole electronic frac fluid flow control and a predetermined module deployed in the well via a flexible, non-metallic, substantially continuous tube and connector [slickline, coil tubing, pumping or any other a means used to deploy hardware in the wellbore].
 17. The method of claim 13, wherein: a. the gauge is deployed without the need for a downhole wired communication connection to the gauge; and b. the predetermined set of data include data useful for at least one of (i) formation monitoring or (ii) pump optimization.
 18. The method of claim 12, wherein: a. the gauge is deployed permanently; b. the container is deployed in the wellbore as part of a drill string and is adapted to interface to a drilling string to retrieve the data from the gauge permanently; and c. the container collects data wirelessly from the gauge while the drilling string is drilling out the seat from a frac sliding sleeves.
 19. A gauge dimensioned and configured for deployment in the wellbore, comprising a. an electronics module, the electronics module comprising: i. a data acquisition module, the data acquisition module dimensioned and configured to measure a predetermined physical phenomenon; ii. an analog to digital converter operatively in communication with the data acquisition module; iii. a processor operatively in communication with at least one of the data acquisition module or the analog to digital converter; iv. a data store operatively in communication with the processor; v. a data transmission module operatively in communication with the processor; and vi. a gauge signal conditioner operatively in communication with at least one of the data transmission module and the data acquisition module; b. a self-resonant coil inductively coupled to the electronics module.
 20. The gauge of claim 19, wherein the predetermined physical phenomenon comprises at least one of pressure and temperature. 